This invention is in the field of hydrocarbon (i.e., oil and gas) production, and is more specifically directed to managing the operation and results of flow testing producing hydrocarbon wells and injecting wells over a production field.
Hydrocarbon production from subterranean reservoirs typically involves multiple wells positioned at various locations of a reservoir. In a given reservoir, the multiple wells are not only deployed at different surface locations, but are also often of different “geometry” from one another, and are also often drilled to different depths. Many typical wells also produce fluids at multiple depths along a single wellbore, thus producing from multiple subsurface strata. As is fundamental in the art, the fluid produced from a given well, as viewed at the wellhead, often includes multiple “phases”, typically natural gas, petroleum or oil, and water. As used herein, the term “phase composition” or simply “phase” in reference to produced fluid refers to the relative amounts of water, oil and gases in the produced fluid. The produced fluid may also contain suspended solids such as sand or asphaltene compounds. In addition, as is well-known in the art, one or more wells into a reservoir may be configured for the injection of fluids, typically gas or water, for secondary recovery and other reservoir management functions. Other injection liquids and gases are used and commercially available for use in secondary recovery and other reservoir management operations, as known in the art.
Knowledge of the rate of production and phase composition of the produced fluids are important properties for effective reservoir management and also for management of individual wells. Reservoir management typically includes the selection of the number of wells to be deployed in a production field, the locations and depths of these wells, the configuration of wells as production or injection wells, and decisions regarding whether to shut-in wells, or convert wells from production to injection wells or vice versa. Well management refers to decisions regarding individual wells, for example decisions regarding whether to perform remedial actions along the wellbore to improve production. Knowledge of production rate and phase information is, of course, also important from an economic standpoint.
Rate and phase information is commonly determined using flow meters or other equipment. For example, separating equipment may be located at or near a wellhead to separate produced phases so that the volume of each phase can be determined. Valves downstream from the separators divert all or a portion of the production stream for a separated phase to a flow meter or the like for measurement of the flow rate of that particular phase. Typically, this diversion is performed only periodically for each phase, for example once per month for a span of twelve hours, because of the effort and flow interruption involved in re-directing the flow of the various phases and because the metering device or separator is required for other production-related purposes. This lack of real-time flow measurements of course reduces confidence in the measurements obtained, and in the decisions made based on those measurements.
In addition to the cumbersome nature of these flow measurements, conventional flow meters generally require frequent calibration to ensure accuracy, considering the typical drift of conventional flow meters over time. Conventional flow meters are also typically calibrated to be accurate only within a certain operating range. If operating conditions change so that the steady-state condition of a well drifts outside the operating range, the flow measurements can be unreliable. In either case, calibration drift or change in operating conditions, the flow meter must be recalibrated, adjusted, or replaced, each action usually requiring physical intervention.
While recalibration and maintenance of flow meters is somewhat cumbersome for land-based wells, the recalibration and maintenance of flow meters is typically prohibitively difficult and costly in marine environments. In addition, the inability to service offshore flow meters can cause total loss of flow measurement if a critical sensor fails. Deep sea marine environments present particularly significant challenges for maintenance or otherwise routine operations. For example, flow meters located within a well or at a wellhead can be prohibitively difficult to recalibrate due to the difficult access for maintenance, as costly intervention vessels and other equipment are often required.
In addition, not all wells in a production field are typically equipped with a dedicated flow meter. Rather, many wells share access to flow meters with other wells in the field. This is especially true in off-shore production, because of the difficulty of maintaining sea-bed downhole sensors in the deep-sea environment. This sharing has been observed to add uncertainty in rate and phase measurements. Typically, in such a shared metering environment, especially offshore, production from several wells is commingled before reaching any platform or other topside facility. As used herein, “topside” in reference to equipment or facilities means equipment or facilities which are located either at or above ground for land-based wells, or at or above the water surface for sea environments (e.g., production platforms and shore-bound surface facilities). In either case, shared topside flow metering typically does not allow determination of production from individual wells without stopping production from other wells.
By way of further background, U.S. Patent Application Publication No. 2004/0084180 describes a method of estimating multi-phase flow rates at each of multiple production string entries located at varying depths along a wellbore, and thus from different production zones of a single well. According to the method of this publication, a volumetric flow rate for each phase is obtained at the wellhead, which of course includes production from each of the downhole production zones. The measured volumetric wellhead flow, along with downhole pressure and temperature measurements, are applied to a well model to iteratively solve for estimates of the flow rate of each phase at each downhole production string entry location.
By way of further background, software packages for modeling the hydraulics of hydrocarbon wells, as useful in the design and optimization of well performance, are known in the art. These conventional modeling packages include the PROSPER modeling program available from Petroleum Experts Ltd, the PIPESIM modeling program available from Schlumberger, and the WELLFLOW modeling program available from Halliburton. These software modeling packages utilize actual measured, or estimated, values of flow, pressure, and temperature parameters to characterize the modeled well and to estimate its overall performance. In addition, these modeling packages can assist in decision making, for example by evaluating the effect on well performance of proposed changes in its operation.
By way of still further background, U.S. Patent Application Publication No. US 2005/0149307 A1, published Jul. 7, 2005, describes the use of well models in reservoir management. Pressure measurements, multi-phase flow rates, etc. are applied to a well production model, and the model is verified based on various well and reservoir measurements and parameters.
The conventional uses of well modeling in well and reservoir management, especially involving the determination of rate and phase values, operate as “snapshots” in time. In other words, the various measurements acquired in the field are applied to the well model “off-line”, with the well model operated by a human engineer or other operator to determine an estimate of the state of the well. Examples of users and operators who operate and analyze the well model in this fashion include, among others, petroleum engineers, reservoir engineers, geologists, operators, technicians, and the like. In many instances, the measurements are obtained or inferred from well tests, such as shut-in tests, during which the well is shut-in suddenly, and the subsequent response of the measured pressure is recorded. Such scheduled well testing is, of course, infrequent in a producing field. And as is well-known in the art, substantial human effort and judgment is often required to select an appropriate well model for a particular set of measurements, to apply judgment and filtering to measurements that appear to be inaccurate, and to evaluate the well model results.
By way of further background, the deployment of downhole pressure and temperature sensors has become increasingly common in recent years, because of improvement in the reliability and long-term performance of such downhole sensors. These modern downhole sensors can now provide measurement data on a continuous and near real time basis, with measurement frequencies exceeding one-per-second.
As is fundamental in the art, modern producing fields include a large number of producing wells. Typically, the split of revenue among royalty participants is uniformly allocated based on the overall output of the field, rather than necessarily allocated based on the output from individual wells in the field, considering that the metering of output from individual wells would be a costly undertaking. As such, the flow from all wells in the field is typically combined and measured as a whole, for example as an overall daily volume from the field. This measurement of the combined output over the field is sufficient for economic purposes, even though the output of individual wells in the field varies to a wide extent.
On the other hand, from the standpoint of well and reservoir management, reservoir engineers or other operators or users are interested in the output of individual wells, both relative to one another within the field and also as such output varies over time and conditions. Knowledge of the output of individual wells enables the timely maintenance of individual wells, should the output drop over time. This knowledge also facilitates management of the reservoir, and optimization of production from the field as a whole. In this regard, optimization of the production response of the field, as a whole, to stimulation, injection, pressure support, and secondary recovery processes, can be attained from knowledge of individual well output over time. And, of course, knowledge of the output of individual wells in the field will greatly assist the placement of new wells.
In conventional production fields, therefore, some capability for measuring the fluid output from individual wells, at least on a periodic or sampled basis, is generally provided. Such periodic or sampled flow measurement of an individual well is referred to in the art as a “flow test”. In a typical flow test, the output stream from a given well is physically isolated from the output of other wells in the field, and directed to a flow meter for measurement over several hours. The flow meter may measure only a separated single phase (i.e., oil, gas, or water) from a selected well, or alternatively may be a “multi-phase” flow meter that simultaneously measures the output of all phases produced from the well. In modern well and reservoir management approaches, the well output is correlated to contemporaneous measurements of reservoir pressure and well flowing pressure at the well under analysis; other parameters such as downhole temperature, surface conditions, in-well flowing pressure, and the like may also be contemporaneously measured and correlated to the meter flow. These measurements thus “calibrate” the pressure and temperature measurements that can be obtained during normal production so that insight into the particular well's flow can be deduced from pressure and temperature measurements. In addition, well and reservoir models can be calibrated by the periodic or sampled flow measurement from individual wells. From an economic viewpoint, these models and parameters, as calibrated by the well flow measurements, can be used to derive an “allocation” of the overall field production to individual wells in the field.
Conventional approaches to flow tests of wells in a production field are generally ad hoc, in that the scheduling and performing of such tests are typically at the discretion and judgment of the reservoir engineers, or other members of the production operations staff. In addition, some level of human judgment is often involved in analysis of the vast amount of data acquired from flow tests over an entire production field. Such judgment is even involved in the determination of which data from a flow test ought to be considered, because some level of instability in the flow conditions is often present in the wells under test, and thus the selection of a “steady-state” measurement period is somewhat subjective. Inconsistency in the treatment of flow test data among different personnel and field locations can preclude accurate comparison of well and field performance over time, or among multiple fields. In addition, the vast amount of data makes conventional processing of flow test results a cumbersome task.